1. Field of the Invention
This invention relates to a process and system for fluidized catalytic cracking of hydrocarbon feedstocks.
2. Description of Related Art
Crude oils are used as feedstocks for producing transportation fuels and petrochemicals. Typically fuels for transportation are produced by processing and blending of distilled fractions from the crude to meet particular end use specifications. While compositions of natural petroleum or crude oils are significantly varied, all crude oils contain organosulfur and other sulfur-containing compounds. Generally, the concentration of sulfur-containing hydrocarbon compounds in whole crude oil is less than about 5 weight percent, with most crude having sulfur concentrations in the range from about 0.5 to about 1.5 weight percent. Because many crude oil sources available today are high in sulfur, the distilled fractions must be desulfurized to yield products which meet performance specifications and/or environmental standards. Even after desulfurization, hydrocarbon fuels can still contain undesirable amounts of sulfur.
There are two basic modes for catalytic conversion of hydrocarbon feedstocks into lower boiling point hydrocarbons. The first mode is the catalytic conversion of hydrocarbon feedstock with added hydrogen at reaction conversion temperatures less than about 540° C. and the reaction zone comprising a fixed bed of catalyst. The second mode is catalytic conversion of hydrocarbons without the addition of hydrogen to the conversion zone, which is typically conducted at temperatures of about 480° C. to about 550° C. using a circulating stream of catalyst.
The first mode, commonly known as a fixed bed hydrocracking processes, has achieved commercial acceptance by petroleum refiners, but this process has several disadvantages. In order to attempt to achieve long runs and high on-stream reliability, fixed bed hydrocrackers require a high inventory of catalyst and a relatively high pressure reaction zone which is generally operated at 150 kg/cm2 or greater to achieve catalyst stability. In addition, two-phase flow of reactants (liquid hydrocarbon feedstock and gaseous hydrogen) over a fixed bed of catalyst often creates uneven distribution within the reaction zone, resulting in inefficient utilization of catalyst and incomplete conversion of the reactants. Further, momentary mis-operation or electrical power failure can cause severe catalyst coking which may require the process to be shut down for offline catalyst regeneration or replacement.
The second mode, commonly referred to as fluidized catalytic cracking (FCC), is well established for conversion of relatively high molecular weight hydrocarbon fractions such as vacuum gas oil and residues into gasoline and other products. FCC is considered to be one of the most important conversion processes used in petroleum refineries, and has certain advantages, including the ability to operate in the absence of an influent hydrogen stream and at relatively low pressure, i.e., about 3 kg/cm2 to about 4 kg/cm2 or less. However, this mode is incapable of upgrading the hydrocarbon product by hydrogenation, and requires relatively high reaction temperatures which accelerate conversion of hydrocarbons into coke thereby decreasing the potentially greater volumetric yield of the normally liquid hydrocarbon product. This coke forms on the catalyst and the FCC processes therefore require catalyst regeneration to burn off the coke and after which the catalyst is recycled.
In typical FCC processes, hydrocarbon feedstock is preheated to 250-420° C. and contacted with hot catalyst at about 650-700° C. either in the reactor or in a catalyst riser associated with the reactor. Catalysts include, for instance, crystalline synthetic silica-alumina, known as zeolites, and amorphous synthetic silica-alumina. The catalyst and the reaction products are separated mechanically in a section of the reactor. The cracked oil vapors are conveyed to a fractionation tower for separation into various products. Catalyst is sent for removal of any oil remaining on the catalyst by steam stripping and regeneration by burning off the coke deposits with air in the regeneration vessel.
In the operation of a conventional oil refinery, various processes occur in discrete units and/or steps. This is generally due to the complexity of naturally occurring crude oil mixtures, and the fact that crude oil feedstocks processed at refineries often differ in quality based on the location and age of the production well, pre-processing activities at the production well, and the means used to transport the crude oil from the well to the refinery plant.
Sulfur-containing hydrocarbon compounds that are typically present in hydrocarbon fuels include aliphatic molecules such as sulfides, disulfides and mercaptans, as well as aromatic molecules such as thiophene, benzothiophene, dibenzothiophene and alkyl derivatives such as 4,6-dimethyl-dibenzothiophene, and aromatic derivatives such as napthenodibenzothiophenes. Those later molecules have a higher boiling point than the aliphatic ones and are consequently more abundant in higher boiling fractions.
The process of these sulfur-containing organic compounds in fuels constitutes a major source of environmental pollution. The sulfur compounds are converted to sulfur oxides during the combustion process and produce sulfur oxyacids and contribute to particulate emissions. Oxygenated fuel blending compounds and compounds containing few or no carbon-to-carbon chemical bonds, such as methanol and dimethyl ether, are known to reduce smoke and engine exhaust emissions. However, most such compounds have high vapor pressures and/or are nearly insoluble in diesel fuel, and also have poor ignition quality. Purified diesel fuels produced by chemical hydrotreating and hydrogenation to reduce their sulfur and aromatics contents also suffer a reduction in fuel lubricity. Diesel fuels of low lubricity may cause excessive wear of fuel pumps, injectors and other moving parts which come in contact with the fuel under high pressure.
In the face of ever-lower government sulfur specifications for transportation fuels, sulfur removal from petroleum feedstocks and products is becoming increasingly important and will be more so in years to come. In order to comply with performance and environmental regulations for ultra-low sulfur content fuels, refiners will have to make fuels having even lower sulfur levels at the refinery.
The aliphatic sulfur compounds are easily desulfurized using conventional HDS methods, but some of the highly branched aliphatic molecules can hinder the sulfur atom removal and are moderately harder to desulfurize. Likewise, the aromatic derivatives are also difficult to remove.
For example, among the sulfur-containing aromatic compounds, thiophenes and benzothiophenes are relatively easy to hydrodesulfurize while the addition of alkyl groups to the ring compounds slightly increases hydrodesulphurization difficulty. Dibenzothiophenes resulting from adding another ring to the benzothiophene family are significantly more difficult to desulfurize and the difficulty varies greatly according to their alkyl substitution with di-beta substitution being the most difficult to desulfurize justifying their “refractory” appellation. These so-called beta substituents hinder the sulfur heteroatom from seeing the active site on the catalyst. HDS units are not efficient to remove sulfur from compounds where the sulfur atom is sterically hindered as in multi-ring aromatic sulfur compounds. This is especially true where the sulfur heteroatom is hindered by two alkyl groups, e.g., 4,6-dimethyldibenzothiophene. However, these hindered dibenzothiophenes predominate at low sulfur levels such as 50 to 100 ppm.
In order to meet stricter sulfur specifications in the future, such hindered sulfur compounds will also have to be removed from distillate feedstocks and products. Hydroprocessing including the conventional hydrodesulfurization and hydrocracking technologies is currently the most accepted route to desulfurize the sulfur-containing hydrocarbon fractions to produce clean fuels.
However, severe operating conditions (i.e., increased hydrogen partial pressure, higher temperature, and catalyst volume) must be applied to remove the sulfur from these refractory sulfur compounds. The increase of hydrogen partial pressure can only be done by increasing the recycle gas purity in existing units. Alternatively, new grassroots units will have to be designed, which is a costly option. The use of severe operating conditions results in yield loss, less catalyst cycle and product quality deterioration (e.g., color).
The economical removal of the so called refractory sulfur is then exceedingly difficult to achieve and therefore the removal of sulfur compounds in hydrocarbon fuels boiling in diesel range to a sulfur level below about 10 ppm is very costly by known current hydrotreating techniques. In order to meet the more stringent sulfur specifications, these refractory sulfur compounds have to be removed from hydrocarbon fuel.
It would be desirable to provide processes and systems that efficiently and economically results in improved hydrocarbon product quality and yield without substantial addition of costly equipment, hardware and control systems to existing facilities.